Over the last two centuries, advances in technology have made our civilization completely oil, gas & coal dependent. Whilst gas and coal are primarily use for fuel oil is different in that immense varieties of products are and can be derived from it. A brief list of some of these products includes gasoline, diesel, fuel oil, propane, ethane, kerosene, liquid petroleum gas, lubricants, asphalt, bitumen, cosmetics, petroleum jelly, perfume, dish-washing liquids, ink, bubble gums, car tires, etc. In addition to these oil is the source of the starting materials for most plastics that form the basis of a massive number of consumer and industrial products.
Table 1 below lists the top 15 consuming nations based upon 2008 data in terms of thousands of barrels (bbl) and thousand of cubic meters per day. FIG. 1A presents the geographical distribution of consumption globally.
TABLE 12008 Oil Consumption for Top 15 Consuming NationsNation(1000 bbl/day)(1000 m3/day)~:1United States19,497.953,099.92China7,831.001,245.03Japan4,784.85760.74India2,962.00470.9SRussia2,916.00463.66Germany2,569.28408.57Brazil2,485.00395.18Saudi Arabia2,376.00377.89Canada2,261.36359.510South Korea2,174.91345.811Mexico2,128.46338.412France1,986.26315.813Iran (OPEC)1,741.00276.814United Kingdom1,709.66271.815Italy1,639.01260.6
In terms of oil production Table 1B below lists the top 15 oil producing nations and the geographical distribution worldwide is shown in FIG. 1B. Comparing Table 1A and Table 1B shows how some countries like Japan are essentially completely dependent on oil imports whilst most other countries such as the United States in the list whilst producing significantly are still massive importers. Very few countries, such as Saudi Arabia and Iran are net exporters of oil globally.
TABLE 2Top 15 Oil Producing NationsNation(1000 bbl/day)Market Share1Saudi Arabia9,76011.8%2Russia9,93412.0%3United States9,14111.1%4Iran (OPEC)4,1775.1%5China3,9964.8%6Canada3,2944.0%7Mexico3,0013.6%8UAE (OPEC)2,7953.4%9Kuwait (OPEC)2,4963.0%10Venezuela (OPEC)2,4713.0%11Norway2,3502.8%12Brazil2,5773.1%13Iraq (OPEC)2,4002.9%14Algeria (OPEC)2,1262.6%15Nigeria (OPEC)2,2112.7%
In terms of oil reserves then these are dominated by a relatively small number of nations as shown below in Table 3 and in FIG. 1C. With the exception of Canada the vast majority of these oil reserves are associated with conventional oil fields. Canadian reserves being dominated by Athabasca oil sands which are large deposits of bitumen, or extremely heavy crude oil, located in northeastern Alberta, Canada. The stated reserves of approximately 170,000 billion barrels are based upon only 10% of total actual reserves, these being those economically viable to recover in 2006.
TABLE 3Top 15 Oil Reserve NationsNationReserves (1000 bbl)Share1Saudi Arabia264,600,00019.00%2Canada175,200,00012.58%3Iran137,600,0009.88%4Iraq115,000,0008.26%5Kuwait104,000,0007.47%6United Arab Emirates97,800,0007.02%7Venezuela97,770,0007.02%8Russia74,200,0005.33%9Libya47,000,0003.38%10Nigeria37,500,0002.69%11Kazakhstan30,000,0002.15%12Qatar25,410,0001.82%13China20,350,0001.46%14United States19,120,0001.37%15Angola13,500,0000.97%
Therefore in the vast majority of wells are drilled into oil reservoirs to extract the crude oil. An oil well is created by drilling a hole 5 to 50 inches (127.0 mm to 914.4 mm) in diameter into the earth with a drilling rig that rotates a drill string with a bit attached. After the hole is drilled, sections of steel pipe (casing), slightly smaller in diameter than the borehole, are placed in the hole. Cement may be placed between the outside of the casing and the borehole to provide structural integrity and to isolate high pressure zones from each other and from the surface. With these zones safely isolated and the formation protected by the casing, the well can be drilled deeper, into potentially more unstable formations, with a smaller bit, and also cased with a smaller size casing. Typically wells have two to five sets of subsequently smaller hole sizes drilled inside one another, each cemented with casing.
Oil recovery operations from conventional oil wells have been traditionally subdivided into three stages: primary, secondary, and tertiary. Primary production, the first stage of production, produces due to the natural drive mechanism existing in a reservoir. These “Natural lift” production methods that rely on the natural reservoir pressure to force the oil to the surface are usually sufficient for a while after reservoirs are first tapped. In some reservoirs, such as in the Middle East, the natural pressure is sufficient over a long time. The natural pressure in many reservoirs, however, eventually dissipates such that the oil must then be pumped out using “artificial lift” created by mechanical pumps powered by gas or electricity. Over time, these “primary” methods become less effective and “secondary” production methods may be used.
The second stage of oil production, secondary recovery, is usually implemented after primary production has declined to unproductive levels, usually defined in economic return rather than absolute oil flow. Traditional secondary recovery processes are water flooding, pressure maintenance, and gas injection, although the term secondary recovery is now almost synonymous with water flooding. Tertiary recovery, the third stage of production, commonly referred to as enhanced oil recovery (“EOR”) is implemented after water flooding. Tertiary processes use miscible and/or immiscible gases, polymers, chemicals, and thermal energy to displace additional oil after the secondary recovery process becomes uneconomical.
Enhanced oil recovery processes can be classified into four overall categories: mobility control, chemical, miscible, and thermal.                Mobility-control processes, as the name implies, are those based primarily on maintaining a favorable mobility ratio. Examples of mobility control processes are thickening of water with polymers and reducing gas mobility with foams.        Chemical processes are those in which certain chemicals, such as surfactants or alkaline agents, are injected to utilize interfacial tension reduction, leading to improved displacement of oil.        In miscible processes, the objective is to inject fluids that are directly miscible with the oil or that generate miscibility in the reservoir through composition alteration. The most popular form of a miscible process is the injection of carbon dioxide.        Thermal processes rely on the injection of thermal energy or the in-situ generation of heat to improve oil recovery by reducing the viscosity of oil.        
In the United States, primary production methods account for less than 40% of the oil produced on a daily basis, secondary methods account for about half, and tertiary recovery the remaining 10%.
Bituminous sands, colloquially known as oil sands or tar sands, are a type of unconventional petroleum deposit. The oil sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as bitumen (or colloquially “tar” due to its similar appearance, odour, and colour). These oil sands reserves have only recently been considered as part of the world's oil reserves, as higher oil prices and new technology enable them to be profitably extracted and upgraded to usable products. They are often referred to as unconventional oil or crude bitumen, in order to distinguish the bitumen extracted from oil sands from the free-flowing hydrocarbon mixtures known as crude oil
Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in two countries: Canada and Venezuela, each of which has oil sand reserves approximately equal to the world's total reserves of conventional crude oil. As a result of the development of Canadian oil sands reserves, 44% of Canadian oil production in 2007 was from oil sands, with an additional 18% being heavy crude oil, while light oil and condensate had declined to 38% of the total.
Because growth of oil sands production has exceeded declines in conventional crude oil production, Canada has become the largest supplier of oil and refined products to the United States, ahead of Saudi Arabia and Mexico. Venezuelan production is also very large, but due to political problems within its national oil company, estimates of its production data are not reliable. Outside analysts believe Venezuela's oil production has declined in recent years, though there is much debate on whether this decline is depletion-related or not.
However, irrespective of such issues the oil sands may represent as much as two-thirds of the world's total “liquid” hydrocarbon resource, with at least 1.7 trillion barrels (270×109 m3) in the Canadian Athabasca Oil Sands alone assuming even only a 10% recovery rate. In October 2009, the United States Geological Service updated the Orinoco oil sands (Venezuela) mean estimated recoverable value to 513 billion barrels (81.6×109 m3) making it “one of the world's largest recoverable” oil deposits. Overall the Canadian and Venezuelan deposits contain about 3.6 trillion barrels (570×109 m3) of recoverable oil, compared to 1.75 trillion barrels (280×109 m3) of conventional oil worldwide, most of it in Saudi Arabia and other Middle-Eastern countries.
Because extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the oil sands must be extracted by strip mining and processed or the oil made to flow into wells by in situ techniques, which reduce the viscosity. Such in situ techniques include injecting steam, solvents, heating the deposit, and/or injecting hot air into the oil sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production. Accordingly, these oil sand deposits were previously considered unviable until the 1990s when substantial investment was made into them as oil prices increased to the point of economic viability as well as concerns over security of supply, long term global supply, etc.
Amongst the reasons for more water and energy of oil sand recovery apart from the initial energy expenditure in reducing viscosity is that the heavy crude feedstock recovered requires pre-processing before it is fit for conventional oil refineries. This pre-processing is called ‘upgrading’, the key components of which are:                1. removal of water, sand, physical waste, and lighter products;        2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN); and        3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR).        
As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil.
Amongst the category of known secondary production techniques the injection of a fluid (gas or liquid) into a formation through a vertical or horizontal injection well to drive hydrocarbons out through a vertical or horizontal production well. Steam is a particular fluid that has been used. Solvents and other fluids (e.g., water, carbon dioxide, nitrogen, propane and methane) have also been used. These fluids typically have been used in either a continuous injection and production process or a cyclic injection and production process. The injected fluid can provide a driving force to push hydrocarbons through the formation, or the injected fluid can enhance the mobility of the hydrocarbons (e.g., by reducing viscosity via heating) thereby facilitating the release of the more mobile hydrocarbons to a production location. Recent developments using horizontal wells have focused on utilizing gravity drainage to achieve better results. At some point in a process using separate injection and production wells, the injected fluid may migrate through the formation from the injection well to the production well thereby “contaminating” the oil recovered in the sense that additional processing must be applied before the oil can be pre-processed for compatibility with convention oil refineries working with the light oil recovered from conventional oil well approaches.
Therefore, a secondary production technique injecting a selected fluid and for producing hydrocarbons should maximize production of the hydrocarbons with a minimum production of the injected fluid, see for example U.S. Pat. No. 4,368,781. Accordingly, the early breakthrough of the injected fluid from an injection well to a production well and an excessive rate of production of the injected fluid is not desirable. See for example Joshi et al in “Laboratory Studies of Thermally Aided Gravity Drainage Using Horizontal Wells” (AOSTRA J. of Research, pages 11-19, vol. 2, no. 1, 1985). It has also been disclosed that optimum production from a horizontal production well is limited by the critical velocity of the fluid through the formation. This being thought necessary to avoid so-called “fingering” of the injected fluid through the formation, see U.S. Pat. No. 4,653,583, although in U.S. Pat. No. 4,257,650 it is disclosed that “fingering” is not critical in radial horizontal well production systems.
The foregoing disclosures have been within contexts referring to various spatial arrangements of injection and production wells, which can be classified as follows: vertical injection wells with vertical production wells, horizontal injection wells with horizontal production wells, and combinations of horizontal and vertical injection and production wells. Whilst embodiments of the invention described below can be employed in all of these configurations the dominant production methodology today relates to the methods using separate, discrete horizontal injection and production wells. This arises due to the geological features of oil sands wherein the oil bearing are typically thin but distributed over a large area. Amongst the earliest prior art for horizontal injection wells with horizontal production well arrangements are U.S. Pat. Nos. 4,700,779; 4,385,662; and 4,510,997.
Within the initial deployments the parallel horizontal injection and production wells vertically were aligned a few meters apart as disclosed in the aforementioned article by Joshi. Associated articles include:                Butler et al in “The gravity drainage of steam-heated heavy oil to parallel horizontal wells” (J. of Canadian Petroleum Technology, pages 90-96, 1981);        Butler in “Rise of interfering steam chambers” (J. of Canadian Petroleum Technology, pages 70-75, vol. 26, no. 3, 1986);        Ferguson et al in “Steam-assisted gravity drainage model incorporating energy recovery from a cooling steam chamber” (J. of Canadian Petroleum Technology, pages 75-83, vol. 27, no. 5, 1988);        Butler et al in “Theoretical Estimation of Breakthrough Time and Instantaneous Shape of Steam Front During Vertical Steamflooding,” (AOSTRA J. of Research, pages 359-381, vol. 5, no. 4, 1989); and        Griffin et al in “Laboratory Studies of the Steam-Assisted Gravity Drainage Process,” (5th Advances in Petroleum Recovery & Upgrading Technology Conference, June 1984, Calgary, Alberta, Canada (session 1, paper 1).        
Vertically aligned horizontal wells are also disclosed in U.S. Pat. Nos. 4,577,691; 4,633,948; and 4,834,179. Staggered horizontal injection and production wells, wherein the injection and production wells are both laterally and vertically spaced from each other, are disclosed in Joshi in “A Review of Thermal Oil Recovery Using Horizontal Wells” (In Situ, Vol. 11, pp 211-259, 1987); Change et al in “Performance of Horizontal-Vertical Well Combinations for Steamflooding Bottom Water Formations,” (CIM/SPE 90-86, Petroleum Society of CIM/Society of Petroleum Engineers) as well as U.S. Pat. Nos. 4,598,770 and 4,522,260.
Amongst other patents addressing such recovery processes are U.S. Pat. Nos. 5,456,315′ 5,860,475; 6,158,510; 6,257,334; 7,069,990; 6,988,549; 7,556,099; 7,591,311 and US Patent Applications 2006/0,207,799; 2008/0,073,079; 2010/0,163,229, 2009/0,020,335; 2008/0,087,422; 2009/0,255,661; 2009/0,260,878; 2009/0,260,878; 2008/0,289,822; 2009/0,044,940; 2009/0,288,827; and 2010/0,326,656. Additionally there are literally hundreds of patents relating to the steam generating apparatus, drilling techniques, sensors, etc associated with such production techniques as well as those addressing combustion assisted gravity drainage etc.
The first commercially applied process was cyclic steam stimulation, commonly referred to as “huff and puff”, wherein steam is injected into the formation, commonly at above fracture pressure, through a usually vertical well for a period of time. The well is then shut in for several months, referred to as the “soak” period, before being re-opened to produce heated oil and steam condensate until the production rate declines. The entire cycle is then repeated and during the course of the process an expanding “steam chamber” is gradually developed where the oil has drained from the void spaces of the chamber, been produced through the well during the production phase, and is replaced with steam. Newly injected steam moves through the void spaces of the hot chamber to its boundary, to supply heat to the cold oil at the boundary.
However, there are problems associated with the cyclic process including:                fracturing tends to occur vertically along a direction dictated by the tectonic regime present in the formation;        steam tends to preferentially move through the fractures and heat outwardly therefrom so that developed chamber tends to be relatively narrow;        low efficiency with respect to steam utilization; and        there are large bodies of unheated oil left in the zone extending between adjacent wells with their linearly extending steam chambers.        
Accordingly, the cyclic process relatively low oil recovery. As such, as described in Canadian Patent 1,304,287, a continuous steam process has become dominant approach, known as steam-assisted gravity drainage (“SAGD”). The approach exploiting:                a pair of coextensive horizontal wells, one above the other, located close to the base of the formation;        the formation between the wells is heated by circulating steam through each of the wells at the same time to create a pair of “hot fingers”;        when the oil is sufficiently heated so that it may be displaced or driven from one well to the other, fluid communication between the wells is established and steam circulation through the wells is terminated;        steam injection below the fracture pressure is initiated through the upper well and the lower well opened to produce draining liquid; and        the production well is throttled to maintain steam trap conditions and to keep the temperature of the produced liquid at about 6-10° C. below the saturation steam temperature at the production well.        
This ensures a short column of liquid is maintained over the production well, thereby preventing steam from short-circuiting into the production well. As the steam is injected, it rises and contacts cold oil immediately above the upper injection well. The steam gives up heat and condenses; the oil absorbs heat and becomes mobile as its viscosity is reduced. The condensate and heated oil drain downwardly under the influence of gravity. The heat exchange occurs at the surface of an upwardly enlarging steam chamber extending up from the wells. This chamber being constituted of depleted, porous, permeable sand from which the oil has largely drained and been replaced by steam.
The steam chamber continues to expand upwardly and laterally until it contacts the overlying impermeable overburden and has an essentially triangular cross-section. If two laterally spaced pairs of wells undergoing SAGD are provided, their steam chambers grow laterally until they contact high in the reservoir. At this stage, further steam injection is terminated and production declines until the wells are abandoned. The SAGD process is characterized by several advantages, including relatively low pressure injection so that fracturing is not likely to occur, steam trap control minimizes short-circuiting of steam into the production well, and the SAGD steam chambers are broader than those developed by the cyclic process.
As a result oil recovery is generally better and with reduced energy consumption and emissions of greenhouse gases. However, there are still limitations with the SAGD process which need addressing. These include the need to more quickly achieve production from the SAGD wells, the need to heat the formation laterally between laterally spaced wells to increase the oil recovery percentage; and provide SAGD operating over deeper oil sand formations.
In SAGD the velocity of bitumen falling through a column of porous media having equal pressures at top and bottom can be calculated from Darcy's Law, see Equation 1.
                              U          O          q                =                                            k              O                        ⁢                          P              O                        ⁢                          g              O                                            μ            O                                              (        1        )            where kO is the effective permeability to bitumen and μO is the viscosity of the bitumen. For Athabasca bitumen at about 200° C. and using 5 as the value Darcy's effective permeability, the resulting velocity will be about 40 cm/day. Extending this to include a pressure differential then the equation for the flow velocity becomes that given by Equation 2.
      U    O    +    =                              k          O                ⁢                  P          O                ⁢        g                    μ        O              +                            k          O                ⁢        Δ        ⁢                                  ⁢        P                              μ          O                ⁢        L            where ΔP is the pressure differential between the two well bores and L is the interwell bore separation. For a typical interwell spacing this results in the value given in Table 1 below.
TABLE 1Increased Bitumen Velocity under Pressure Differentialk0Δ/μ0Lk0P0g/μ0 = U0qU0+ΔP (psia)(cm/day)(cm/day)(cm/day)U0+/U0g0.000.00039.439.41.000.010.04639.439.51.000.100.42739.439.91.011.004.41039.443.81.1110.0044.20039.483.62.1250.00220.839.4260.06.60
It is evident from the data presented in Table 1 that a pressure differential can substantially increase the mobility of the heavy oil in oil sand deposits. Considering the Athabasca oil sands about 20 percent of the reserves are recoverable by surface mining where the overburden is less than 75 m (250 feet). It is the remaining 80 percent of the oil sands that are buried at a depth of greater than 75 m where SAGD and other in-situ technologies apply. Typically, pressure increases at an average rate of approximately 0.44 psi per foot underground, such that the pressure at 250 feet is 110 psi higher than at the surface, at 350 feet it is 154 psi higher. For comparison atmospheric pressure is approximately 14.7 psi, such that the pressure at 350 feet is approximately 10 atmospheres.
Accordingly, the inventor has established that beneficially pressure differentials may be exploited to advance production from SAGD wells by increasing the velocity of heavy oils, that pressure differentials may be exploited to adjust the evolution of the steam chambers formed laterally between laterally spaced wells to increase the oil recovery percentage, and provide SAGD operating over deeper oil sand formations.